Philip J. Passanante Assistant General Counsel

92DC42 302.429.3105 - Telephone PO Box 6066 302.429.3801 - Facsimile Newark, DE 19714-6066 [email protected]

500 N. Wakefield Drive atlanticcityelectric.com Newark, DE 19702

July 1, 2021

VIA ELECTRONIC MAIL [email protected] board.secretary@bpu. nj.gov

Aida Camacho-Welch Secretary of the Board Board of Public Utilities 44 South Clinton Avenue, 9th Floor P.O. Box 350 Trenton, New Jersey 08625-0350

RE: In the Matter of the Provision of Basic Generation Service (“BGS”) for the Period Beginning June 1, 2022 BPU Docket No. ER21030631

Dear Secretary Camacho-Welch:

In accordance with the Preliminary 2022 BGS Schedule set forth in the New Jersey Board of Public Utilities’ (the “Board” or “BPU”) April 7, 2021 Decision and Order in the above- referenced matter, enclosed please find Atlantic City Electric Company’s (“ACE”) Company- Specific Addendum proposal for the Energy Year beginning June 1, 2022.

Pursuant to the terms of the Preliminary 2022 BGS Schedule referenced above, a generic Proposal for the Basic Generation Service to Be Procured Effective June 1, 2022 (the “BGS Proposal”) has been contemporaneously filed by Public Service Electric and Gas Company on behalf of all New Jersey electric distribution companies (“EDCs”), including ACE. The BGS Proposal describes the BGS auction process, including the pre-qualification of bidders, setting of starting prices, BGS pricing and rate design methodology, and the respective roles of the EDCs and the Board. The BGS Proposal also includes the proposed Supplier Master Agreements.

The BGS Proposal and ACE’s Company-Specific Addendum can also be accessed on the BGS Auction website at http://bgs-auction.com/bgs.auction.regproc.asp.

Aida Camacho-Welch July 1, 2021 Page 2

Consistent with the Order issued by the Board in connection with In the Matter of the New Jersey Board of Public Utilities’ Response to the COVID-19 Pandemic for a Temporary Waiver of Requirements for Certain Non-Essential Obligations, BPU Docket No. EO20030254, Order dated March 19, 2020, this document is being electronically filed with the Secretary of the Board, the Division of Law, the New Jersey Division of Rate Counsel and the Service List. No paper copies will follow.

Thank you for your cooperation and courtesies. Feel free to contact the undersigned with any questions.

Respectfully submitted,

Philip J. Passanante An Attorney at Law of the State of New Jersey

Enclosure

cc: Service List

IN THE MATTER OF THE STATE OF NEW JERSEY PROVISION OF BASIC BOARD OF PUBLIC UTILITIES GENERATION SERVICE FOR THE PERIOD BEGINNING BPU DOCKET NO. ER21030631 JUNE 1, 2022

ATLANTIC CITY ELECTRIC COMPANY

BASIC GENERATION SERVICE COMMENCING JUNE 1, 2022

COMPANY-SPECIFIC ADDENDUM COMPLIANCE FILING July 1 , 2021

ACE Company-Specific Addendum

ATLANTIC CITY ELECTRIC COMPANY’S COMPANY-SPECIFIC ADDENDUM

The following contains the company-specific material (referred to herein as the

“Addendum”) of Atlantic City Electric Company ("ACE" or the “Company”) for the joint compliance filing made with the New Jersey Board of Public Utilities (the “Board” or “BPU”) on this date by the Electric Distribution Companies (the "EDCs") in this docket. Capitalized terms used herein shall have the meanings defined in the joint filing.

As described in the generic section of this filing, two (2) different methods will be utilized for the pricing of Basic Generation Service (“BGS”) to customers – residential and small commercial energy pricing and variable hourly energy pricing. The residential and small commercial energy pricing formerly referred to as “Basic Generation Service–Fixed Price” or

“BGS-FP”1 now termed “Basic Generation Service–Residential Small Commercial Pricing” or

“BGS-RSCP” and the hourly energy pricing service termed “Basic Generation Service –

Commercial and Industrial Energy Pricing” or “BGS- CIEP.” BGS-RSCP is to be available to all residential and small commercial customers, specifically those customers taking service on Rate

Schedules RS, MGS (Secondary, Secondary Electric Vehicle Charging, and Primary), AGS

(Secondary and Primary), DDC, SPL, and CSL. These rate classes comprise the vast majority of

ACE’s customers and approximately 87% of the usage on the ACE electric system. As described in detail later in this filing, BGS-RSCP commercial or industrial customers can opt in to BGS-

CIEP.

1 In this document, “Basic Generation Service-Fixed Price” or “BGS-FP” has the same meaning as, and is entirely interchangeable with, “Basic Generation Service-Residential Small Commercial Pricing” or “BGS-RSCP.”

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ACE Company-Specific Addendum

BGS-CIEP will continue to be the only default supply option available to customers taking

service under ACE's Rate Schedule TGS (Transmission General Service). Pursuant to the

Board’s Decision on June 18, 2012, in BPU Docket No. ER12020150, changing the BGS-CIEP

required customer capacity peak load share (“PLS”) to 500 kW or greater effective June 1, 2013,

will be the only default supply option available to customers on Rate Schedules MGS Secondary,

MGS Primary, AGS Secondary or AGS Primary with an annual PLS for generation capacity equal

to or greater than 500 kW as of November 1 of the year prior to the BGS auction. There are an estimated 232 eligible CIEP customers representing approximately 13% of the usage on the

ACE electric system, whose only default supply option is BGS-CIEP. As described in detail later in this filing, BGS-CIEP will also be available to any commercial or industrial customer on a voluntary basis, regardless of such customer’s regular Rate Schedule.

A. COMMITTED SUPPLY

“Committed Supply” means power supplies to which ACE has an existing physical or

financial entitlement. For ACE, Committed Supply includes its Non-Utility Generation (“NUG”) contracts, including any restructured replacement power contracts, which may extend into or through the BGS bid period. ACE retains the right to negotiate changes in, and operational control over, all of its NUG contracts.

As a result of the Board’s December 18, 2002 Order in BPU Docket Nos. EX01110754 and EO02070384, effective August 1, 2003, ACE’s NUG-related Committed Supply (capacity, energy, and ancillaries, if any) is being sold in the wholesale markets. NUG-related capacity, energy, and ancillaries (if any) will continue to be sold in the wholesale markets. These sales shall be considered prudent unless and until the Board determines that a different protocol is appropriate.

Just as they are currently, ACE’s actual above-market NUG contract costs will continue to be

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ACE Company-Specific Addendum

charged to the Non-Utility Generation Charge (“NGC”) clause, with full and timely cost recovery

assured, and subject to deferral in accordance with ACE's restructuring order. In setting the

NGC, the actual NUG contract costs will be offset with revenues received from the sale of NUG power in the wholesale markets.

If ACE is required to invoke the Contingency Plan (discussed at length below), Committed

Supply may be used to offset requirements associated with the Contingency Plan. Any generation from ACE's Committed Supply that qualifies as a Class I or Class II renewable resource will be used to meet the Renewable Portfolio Standards (“RPS”) requirements, and, since ACE has no

BGS supply requirements, it will, to the extent permitted by applicable regulatory and contractual provisions, be credited on a pro-rata basis to winning BGS-RSCP and BGS-CIEP suppliers. This will assure that these environmental benefits are retained by BGS customers in ACE’s service territory. Winning BGS-RSCP and BGS-CIEP suppliers will be responsible for obtaining and providing related verification information to ACE for the minimum Class I and Class II percentages required by the RPS associated with the tranches they serve, net of renewable attributes of the Committed Supply energy proportionately applied and subject to the foregoing limitations to each supplier’s tranches.

The ACE NUG-related Committed Supply subject to the foregoing limitations eligible to supply the Class II renewable energy certificate to the BGS suppliers expired on September 5,

2016.

B. CONTINGENCY PLANS

While not every contingency can be anticipated, ACE can differentiate four (4) areas of concern as follows:

a) there are an insufficient number of bids to provide for a fully subscribed Auction Volume either for the BGS-RSCP auction or the BGS-CIEP auction;

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ACE Company-Specific Addendum

b) a default by one of the winning bidders prior to June 2022;

c) a default during the June 1, 2022 - May 31, 2023 supply period, under the BGS- CIEP contracts entered into for 12 months; and/or

d) a default during the June 1, 2022 - May 31, 2025 supply period, under the BGS-RSCP contracts entered into for 36 months.

1. Insufficient Number of Bids in Auction

To ensure that the auction process achieves the best price for customers, the degree of

competition in the auction must be sufficient. To ensure a sufficient degree of competition, the volume of BGS-RSCP and BGS-CIEP Load purchased at each auction will be finally decided after the first round of bids are received. Provided that there are sufficient bids at the starting prices, the auctions will be held for 100% of BGS-RSCP and BGS-CIEP Loads.

It is possible that the number of initial bids will not result in a competitive auction for

100% of the BGS-RSCP or BGS-CIEP Load. This determination will be made by the Auction

Manager in consultation with the EDCs, and the Board Advisor.

In the event that the Auction Volume is reduced to less than 100% of BGS-RSCP or

BGS-CIEP Load, ACE, at its option, will implement a Contingency Plan for the remaining tranches. Under the Plan, ACE will purchase necessary services (including, but not limited to, network transmission, capacity, energy and ancillary services, and any required RPS Renewable

Energy Certificate) for the remaining tranches through PJM-administered markets until May 31,

2023 and may retain Committed Supply to serve these tranches. Any unsubscribed tranches for the period after May 31, 2023, may be included in a subsequent auction or treated pursuant to the provisions of part 4 of the Contingency Plan described below. This Contingency Plan will alert bidders that, in order to secure BGS-RSCP and BGS-CIEP prices from New Jersey BGS customers for their supply, it will be necessary to bid in to the auctions.

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ACE Company-Specific Addendum

Since the Contingency Plan calls for the purchase of BGS supply in PJM-administered

markets, it is considered a prominent feature of the auction proposal because it provides bidders a strong incentive to participate in the auction process. If bidders were to believe that a less than

fully subscribed auction would lead to a negotiation or a secondary market in which ACE, on

behalf of its customers, would seek to acquire BGS supplies, the incentive to participate in the auctions and the incentive to offer the best deal in the auctions would be subsequently diminished.

2. Defaults Prior to June 1, 2022

If a winning bidder defaults prior to the beginning of the BGS service, then, at ACE’s option, the open tranches may first be offered to the other winning bidders or will be filled as provided in part 3, below. Additional costs incurred by ACE in implementing the Contingency

Plan will be assessed against the defaulting suppliers' credit security.

3. Defaults During the June 1, 2022 - May 31, 2023 Supply Period

If a default occurs during the June 1, 2022 - May 31, 2023 period, for those contracts entered into for 12 months, at ACE’s option, the tranches supplied by the defaulting supplier may be offered to the other winning bidders, may be bid out or may be procured from PJM- administered markets, and Committed Supply may be retained to serve these tranches. Additional costs incurred by ACE in implementing this part of the Contingency Plan will be assessed against the defaulting suppliers' credit security.

If circumstances are such that it is not practical to find another such supplier, ACE proposes to utilize a process similar to the "flexible portfolio approach" for BGS wholesale supply, as previously described in ACE's filing in BPU Docket No. EM00080604, as noted in the Board's

November 29, 2000 Order in that docket. This approach relies on a combination of competitive sources for BGS power, including Requests for Proposal(s), broker markets, capacity costs based

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ACE Company-Specific Addendum

on the PJM Reliability Pricing Model (“RPM”), and the PJM spot energy market.

4. Defaults During the June 1, 2022 - May 31, 2025 Supply Period

If a default occurs during the June 1, 2022 - May 31, 2025 period, for those contracts entered into for 36 months, at ACE’s option, the tranches supplied by the defaulting supplier may be offered to the other winning bidders, may be bid out or may be procured from PJM- administered markets, and Committed Supply may be retained to serve these tranches. Among the options for bidding out the tranches, ACE may include such tranches in the next BGS procurement. Additional costs incurred by ACE in implementing this part of the Contingency

Plan will be assessed against the defaulting suppliers' credit security.

If circumstances are such that it is not practical to find another such supplier, ACE proposes to utilize a process similar to the "flexible portfolio approach" for BGS wholesale supply, as previously described in the Company's filing in BPU Docket No. EM00080604, as noted in the

Board's November 29, 2000 Order in that docket. This approach relies on a combination of competitive sources for BGS power, including requests for proposal, broker markets, capacity costs based on the PJM RPM, and the PJM spot energy market.

C. ACCOUNTING AND COST RECOVERY

The accounting and cost recovery that ACE will use for its BGS service is summarized in

this Section. These provisions are intended to be applicable to ACE only. Each EDC will

provide these individual BGS cost recovery methodologies.

ACE’s BGS accounting will account for BGS-RSCP revenues and BGS-CIEP revenues individually as follows:

1. BGS-RSCP and BGS-CIEP revenues will be tracked using established

accounting procedures and recorded separately as BGS-RSCP revenue and BGS-

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ACE Company-Specific Addendum

CIEP revenue; and

2. as previously established for ACE, uncollectible revenues are recovered through

a component of ACE's Societal Benefits Charge.

ACE will account for BGS-RSCP and BGS-CIEP costs individually as the sum of the following:

1. all payments made for the provision of BGS-RSCP and BGS CIEP service,

including CIEP Standby Fee payments; and

2. any administrative costs associated with the provision of BGS-RSCP and BGS-

CIEP service:

a. Administrative costs are defined as commonly-incurred or directly-

incurred. Commonly-incurred costs are costs shared among all of the New

Jersey EDCs. Directly-incurred costs are costs specifically incurred by

each EDC, individually.

Commonly-incurred costs include, but are not limited to, the following:

• preparing and conducting the annual auction, which include all pre- auction development work, developing and printing materials, developing and maintaining the BGS auction website, conducting information sessions for prospective bidders, as well as other consulting services provided by the Auction Manager; • oversight of the auction process on behalf of the BPU, as performed by the Board’s consultant; • rent and maintenance of office space in New Jersey for the Auction Manager; • outside counsel legal costs associated with the prosecution and/or defense of BGS patent claims; and • facility costs associated with viewing the annual auction in real time, which include, but are not limited to, costs for physical space and equipment/media connections.

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ACE Company-Specific Addendum

Directly-incurred costs for ACE include, but are not limited to, the following:

• labor costs and expenses associated with employees who are considered incremental to the BGS process; • system and software costs related to tracking BGS costs and invoicing; • power procurement residual costs; and • other administrative fees incurred in connection with the BGS process, including, but not limited to, fees/licenses, costs associated with public hearings, postage, and information technology support and programming changes necessitated by BPU directives.

The commonly-incurred cost estimates for each BGS Auction cycle are paid for

by the winning bidders of the auction at the start of each Energy Year through

the Tranche Fee. The difference between the estimated commonly-incurred

costs and the actual commonly-incurred costs and all the directly-incurred costs

are paid through the BGS Reconciliation Charges.

As noted, one element of commonly-incurred costs has been the costs

associated with the rent and maintenance of office space in New Jersey for the

Auction Manager to conduct the annual BGS Auction. Due to restrictions and

safeguards related to the COVID-19 pandemic, the February 2021 BGS

Auction was conducted remotely (i.e., the aforementioned office space was not

utilized), without issue. Given the success of conducting the recent auction in

this manner, ACE believes that it would be prudent (and will reduce costs for

the benefit of BGS customers) to conduct future BGS Auctions in this same

remote manner. As such, the Company proposes to begin the process of

subletting or otherwise closing the physical BGS office located in Newark, N.J.,

in an effort to eliminate the costs related to the same; and

3. any cost for procurement of capacity, energy, ancillary service, transmission,

RPS compliance, and other expenses related to the Contingency Plan, and any

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ACE Company-Specific Addendum

payments to the winners of a subsequent bid process to cover defaults made under

the Contingency Plan, less any payments recovered from defaulting bidders. In the

event that implementation of the Contingency Plan is required for BGS CIEP load,

CIEP Standby Fee payments will be tracked separately.

BGS-RSCP and BGS-CIEP rates will be subject to deferred accounting since there will be differences between the BGS costs (as defined above) and BGS-related revenues. Adjustment type charges (also subject to deferred accounting) are necessary in order to balance out the difference between the amount paid to the BGS-RSCP and BGS-CIEP supplier(s) for BGS-RSCP and BGS-CIEP supply, and the revenue from customers for BGS-RSCP and BGS-CIEP services.

These reconciliation charges (“RC”), including interest, will be calculated periodically for BGS-

RSCP and BGS-CIEP on a cent per kWh basis, and the respective rates will be applied to all BGS-

RSCP and BGS-CIEP kWh. These charges will be combined with the fixed, seasonally- differentiated BGS-RSCP and hourly BGS-CIEP charges for billing although they will be published in ACE’s Rider BGS as separate BGS-RSCPRC and BGS-CIEPRC rates that will be revised periodically.

A BGS deferral/credit will be determined individually for the BGS-RSCP and BGS-CIEP rates as the difference between recorded BGS-RSCP or BGS-CIEP revenue and the total BGS-

RSCP or BGS-CIEP cost. The individual BGS deferrals will be accounted for in the following manner:

1. If individual BGS costs, as defined above, are higher than individual BGS recorded

revenue, the difference will be charged on a monthly basis to the cost deferral to

be reconciled and recovered from customers, with interest, on a periodic, basis

through the BGS-RSCPRC and/or the BGS-CIEPRC.

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ACE Company-Specific Addendum

2. If individual BGS costs, as defined above, are lower than individual BGS recorded

revenue, the difference will be credited monthly, to the cost deferral to be

reconciled and returned to customers, with interest, on a periodic basis, through the

BGS-RSCPRC and/or BGS-CIEPRC.

An additional deferred balance will be maintained individually for the BGS-RSCPRC and

BGS-CIEPRC rates to ensure full recovery of all of the costs associated with the provision of BGS service.

In the event that the Contingency Plan is required to be implemented to serve BGS-CIEP load, the difference between CIEP Standby Fee revenues and CIEP Standby Fee payments made to winning BGS-CIEP auction bidders will be maintained in a separate deferred balance account.

Interest on this account will be accrued monthly, using the same methodology and interest rate as used for the BGS-RSCP and BGS-CIEP deferred balances. Any debit/credit balance in this account at the end of the BGS period of June 1, 2022 through May 31, 2023 will be applied as a

$/kWh adjustment to the CIEP Standby Fee for the next BGS-CIEP annual period. In this manner, the mechanism to reconcile any CIEP Standby Fee deferred balance is applied, to the greatest extent practicable, to all BGS-CIEP eligible customers who paid the CIEP Standby Fee, and not only to those taking BGS-CIEP service.

With the exception of any adjustment to the CIEP Standby Fee which may be required,

ACE will follow the following schedule for the periodic reconciliation of its BGS-RSCP and BGS-

CIEP rates:

1. For BGS-RSCPRC and BGS-CIEPRC rates effective June 1, the actual data for

the months of August through March will be used. Projected data for April and

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ACE Company-Specific Addendum

May will be used for the amount of BGS-RSCPRC and BGS-CIEPRC to be

recovered/returned in those months.

2. For BGS-RSCPRC and BGS-CIEPRC rates effective October 1, the actual data

for the months of April through July will be used. Projected data for August and

September will be used for the amount of BGS-RSCPRC and BGS-CIEPRC to be

recovered/returned in those months.

ACE will file BGS-RSCPRC and BGS-CIEPRC rates with the Board at least 30 days in advance

of the date upon which they are requested to be effective. The BGS Reconciliation Rate is capped

at two cents per kWh. The filed rates will become effective 30 days after filing, absent a

determination of manifest error by the Board.

D. DESCRIPTION OF BGS TARIFF SHEETS

This Section describes the proposed tariff sheets needed to implement ACE’s BGS proposal. The proposed tariff sheets for Tariff Rider Basic Generation Service (“Rider BGS”) are included as Attachment 1. Rider BGS provides the rates, terms, and conditions for customers being served under the BGS-RSCP or BGS-CIEP pricing mechanisms.

1. BGS-RSCP

BGS-RSCP is to be available to all customers served on Rate Schedules RS, DDC, SPL,

and CSL. BGS-RSCP is also available to customers with a PLS of less than 500 kW who are

served under Rate Schedules MGS Secondary, MGS Secondary Electric Vehicle Charging, MGS

Primary, AGS Secondary, and AGS Primary. On any meter reading date, and with prior requisite

notice, a customer taking supply service under BGS-RSCP may switch to third-party supply

service, and a customer taking third-party supply service may switch to BGS-RSCP supply service.

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ACE Company-Specific Addendum

As indicated on the proposed tariff sheets, BGS-RSCP is made up of two components:

BGS Supply Charges and the BGS Reconciliation Charge. Additionally, each BGS customer is subject to transmission charges as discussed below.

a. BGS Supply Charges

The values of the BGS Supply charges applicable to Rate Schedules RS, MGS Secondary,

MGS Secondary Electric Vehicle Charging, MGS Primary, AGS Secondary, AGS Primary, DDC,

SPL, and CSL include the costs related to energy, generation capacity, RPS, ancillary services, and administration. This is a continuation of the current approved methodology for recovering

all electric supply service costs in the kilowatt- hour charges for these Rate Schedules.

Typically, the generation capacity costs used in the development of the BGS-RSCP rates are the relevant current wholesale market prices for capacity based on the average, 2022/2023,

2023/2024, and 2024/2025 Base Residual Auctions (“BRA”) results under the RPM applicable to load served in the ACE zone. This process has been impacted in recent years by delays in conducting the BRAs – resulting in the need for contract supplements with Capacity Proxy prices.

However, PJM has issued a schedule of upcoming BRAs, and the recently conducted BRA produced a preliminary price paid for capacity of $97.75 per MW-day for the 2022/2023 Delivery

Year for the ACE Zone. Due to the postponement of the BRAs, contracts from the 2020 and 2021

BGS auctions contained supplements with Capacity Proxy Prices. With the prior postponements of the BRAs for the 2022/2023 and 2023/2024 Delivery Years, a Capacity Proxy Price of $152.06 per MW-Day and $146.51 per MW-Day were used in place of the 2022/2023 and 2023/2024 BRA values respectively.

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ACE Company-Specific Addendum

Given the continued delay in the schedule of BRAs for the 2023/2024 Delivery Year and

2024/2025 Delivery Year, a Capacity Proxy Price of $118.12 per MW-Day and a Capacity Proxy

Price of $87.98 per MW-Day have been used in place of the prices paid for capacity for 2023/2024 and 2024/2025 Delivery Years, respectively.

For Energy Year (“EY”) 2024, if Supplement A to the BGS-RSCP Supplier Master

Agreement is approved by the BPU and the BRA for the 2023/2024 Delivery has not occurred at least 20 business days prior to the BGS-RSCP Auction, payments to BGS-RSCP suppliers will be adjusted for the difference between the “Zonal Capacity Price,” which is the price paid by BGS-

RSCP Suppliers for Capacity in the Company’s PJM zone, as may be determined under the RPM or its successor or otherwise, and the Capacity Proxy Price for the 2023/2024 Delivery Year.

For EY 2025, if Supplement B to the BGS-RSCP Supplier Master Agreement is approved by the BPU and the BRA for the 2024/2025 Delivery has not occurred at least 20 business days prior to the BGS-RSCP Auction, payments to BGS-RSCP suppliers will be adjusted for the capacity price difference between the Zonal Capacity Price, which is the price paid by BGS-RSCP

Suppliers for Capacity in the Company’s PJM zone, as may be determined under the RPM or its successor or otherwise, and the Capacity Proxy Price for the 2024/2025 Delivery Year.

ACE will file new tariff sheets for EY 2024 and EY 2025, reflecting the impact of this price adjustment in a manner similar to Attachment 4, page 1 – Development of Capacity Proxy

Price True Up - $/MWh. The rate design spreadsheets include the formulas that will be used to reflect the impact of payments made pursuant to the Supplements. However, the spreadsheets do not provide a value for the EY 2024 and EY 2025 true-ups as the actual values are not known at this time. Attachment 4, pages 2 and 3 provide illustrative examples of how the Capacity Proxy

Price True Up will be calculated for EY 2024 and EY 2025 respectively and prospectively.

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ACE Company-Specific Addendum

The Supplements to the SMAs signed by BGS-RSCP Suppliers in February 2020 and

February 2021 are still in effect for approximately two-thirds of the load for Energy Year 2023

(the year beginning June 1, 2022). Payments to BGS-RSCP suppliers that executed the

Supplements to the SMAs approved by the BPU on November 13, 2019 and November 18, 2020 will be adjusted for the price difference between the price paid by BGS-RSCP Suppliers for

Capacity in the Company’s PJM Zone and the Capacity Proxy Price for the 2022/2023 Delivery

Year. Upon the conclusion of the Third Incremental RPM Auction, or the RPM’s successor or otherwise, the price paid by BGS-RSCP Suppliers for Capacity in the Company’s PJM Zone will

be known. At that time ACE will file new tariff sheets reflecting the impact of the Supplements.

The rate design spreadsheets include the formulas that will be used to reflect the impact of

payments made pursuant to the Supplements executed by BGS-RSCP Suppliers in February 2020 and February 2021. The value of the recently conducted BRA in June of 2021 is used as an approximation for the price paid by BGS-RSCP Suppliers for Capacity in the Company’s PJM

Zone for the 2022/2023 Delivery Year ($97.75 per MW-Day).

The specific values that will be utilized for the BGS Supply Charges will be calculated

as the tranche-weighted average of the winning BGS-RSCP bid prices for the ACE zone (the winning bid from the 2020/2021 auction will have transmission charges removed by the method shown in Attachment 5 – Development of Assumed Transmission Price in Bid), adjusted for the seasonal payment factors for ACE's Atlantic Electric zone, adjusted by the appropriate factor (multiplier and constant, if applicable) as shown on Table No. 14 of the

Development of Post Transition Period BGS Cost and Bid Factor Tables, included in Attachment

2.

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ACE Company-Specific Addendum

It is the intent of ACE that the factors in the tables will be applied to the tranche-weighted average of the winning BGS-RSCP bid prices adjusted for the seasonal payment factors. For the period beginning June 1, 2022, the pricing will be based on the 36-month auction price, the

36-month price from the auction held in February 2021 and the 36-month price from the auction

held in February 2020. The tables will be updated annually prior to future BGS auctions and will be utilized to develop customer charges for a related annual period in a similar manner as described above. The updates will reflect then current factors such as updated futures prices, factors based on 12-month data, and any changes in the customer groups and loads eligible for the BGS-RSCP class.

b. BGS Reconciliation Charge

This is the implementation of the BGS Reconciliation Charge for BGS-RSCP as explained in the Accounting and Cost Recovery section of this Addendum.

c. Transmission Charges

Transmission service will continue to be billed under the rates, terms, and conditions of the customer's applicable Rate Schedule as set forth in the ACE Tariff for Electric Service. The transmission charges applicable to ACE’s BGS-RSCP customers are based on the annual

transmission rate for network service for the ACE zone, as stated in PJM’s Open Access

Transmission Tariff (“OATT”). As part of a settlement approved by the Federal Energy

Regulatory Commission (“FERC”) on August 9, 2004, certain transmission owners in PJM,

including ACE, agreed to re-examine their existing rates, and to propose a method (such as a

formula rate) to harmonize new and existing transmission investments by January 31, 2005, with

such new rate(s) (if any) to go into effect June 1, 2005. The objective of the formula rate filing

is to establish a just and reasonable method for determining the transmission revenue requirements

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ACE Company-Specific Addendum

for the affected transmission pricing zones which would reflect both existing and new investment

on a current basis. The formula rate tracks increases and decreases in costs such that no under-

and no over-recovery of actual costs will occur. The formula rate protocols include provisions for an annual update to the rate based on current levels of costs and reconciliation of prior period costs and revenues. Pursuant to the protocols established in the settlement, the Company will file updates to the formula rate at FERC on or about May 15 of each year to be effective on June

1 of that same year. The Company will make corresponding filings with the Board each year seeking approval of the formula rates on a retail level.

In addition to the formula rate protocols described above, the transmission charge may change from time to time as FERC approves other changes in the PJM OATT and related charges.

The transmission cost component of the BGS-RSCP charges to customers will change from time to time as FERC approves changes in the Network Integration Transmission Service rates for the ACE zone in the PJM OATT or FERC approves other network transmission-related charges

in the PJM OATT.

ACE will provide the basis for any transmission cost adjustment, and will file supporting documentation from the OATT, as well as any rate translation spreadsheets used.

For prior BGS Contract EY 2020, the BGS price will be adjusted to remove the BGS

Transmission Charge as shown in Attachment 5 - Development of Assumed Transmission Price in Bid. The Transmission Obligations and kWh used per tranche are the same as were used in the

BGS Pricing Spreadsheet at the time of the BGS Auction held in February of 2020.

2. BGS-CIEP

BGS-CIEP will be the only default supply option available to customers served on Rate

Schedule TGS (Transmission General Service), and to customers served on Rate Schedules

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ACE Company-Specific Addendum

MGS Secondary, MGS Secondary Electric Vehicle Charging, MGS Primary, AGS Secondary, and

AGS Primary with a PLS of 500 kW and higher as of November 1 of the year prior to the BGS auctions. Additionally, BGS-CIEP is available on a voluntary basis to any commercial or industrial customer taking service under the MGS or AGS Rate Schedules. To be eligible for

BGS-CIEP, the customer will need to notify ACE of its choice no later than the second working day of a given year and must commit to having BGS-CIEP as its default supply service

option for a 12-month period commencing June 1st of that year. All commercial and industrial

customers taking service under the MGS or AGS Rate Schedules will be notified of their option

to switch to BGS-CIEP through the Company’s website and tariffs. Customers who elected BGS-

CIEP in a prior procurement period and who are eligible to receive BGS-RSCP service may return

to BGS-RSCP if they notify ACE of their intent to return to BGS-RSCP default service no later

than the second working day of January. Such election will be effective on June 1st of that year.

The charges for BGS-CIEP are comprised of three segments: BGS Energy Charges, BGS

Capacity Charges, and the BGS Reconciliation Charges. Transmission service will continue to be billed under the rates, terms, and conditions of the customer's applicable Rate Schedule as set forth in the ACE Tariff for Electric Service. The transmission charges applicable to ACE’s BGS-CIEP customers are based on the annual transmission rate for network service for the ACE zone, as stated in PJM’s OATT. As part of a settlement approved by FERC on August 9, 2004, certain transmission owners in PJM, including ACE, agreed to re-examine their existing rates and to propose a method (such as a formula rate) to harmonize new and existing transmission investments

by January 31, 2005, with such new rate (if any) to go into effect June 1, 2005. The objective of

the formula rate filing is to establish a just and reasonable method for determining the transmission

revenue requirements for the affected transmission pricing zones which would reflect both

existing and new investment on a current basis. The formula rate tracks increases and decreases

17

ACE Company-Specific Addendum

in costs such that no under- and no over-recovery of actual costs will occur. The formula rate

protocols include provisions for an annual update to the rate based on current levels of costs, and

reconciliation of prior period costs and revenues. Pursuant to the protocols established in the

settlement, the Company will file updates to the formula rate at FERC on or about May 15 of

each year, to be effective on June 1 on that year. The Company will make corresponding filings

with the Board each year seeking approval of the formula rates on a retail level.

In addition to the formula rate protocols described above, the transmission charge may

change from time to time as FERC approves other changes in the PJM OATT and related charges.

The transmission cost component of the BGS-CIEP charges to customers will change from time

to time as FERC approves changes in the Network Integration Transmission Service rates for

the ACE zone in the PJM OATT or FERC approves other network transmission-related charges

in the PJM OATT.

ACE will provide the basis for any transmission cost adjustment, and will file supporting

documentation from the OATT, as well as any rate translation spreadsheets used.

a. BGS Energy Charge

One of the primary components of this charge will be the actual real time PJM load-weighted average Residual Metered Load Aggregate Locational Marginal Price (“LMP”), of energy for ACE's Atlantic Electric Transmission Zone. An estimate of the Ancillary Service cost for the ACE zone expressed on a dollar per MWh basis and administrative costs will be added to this charge. This sum will then be adjusted for losses for service according to the Rate

Schedule for which this service is applicable.

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ACE Company-Specific Addendum

b. BGS Capacity Charges

These charges will recover the costs associated with generation capacity. Effective with

the supply period beginning June 1, 2009, the BGS Capacity Charge is based on the results of the

BGS-CIEP auction process. This charge, Sales and Use Tax (“SUT”), and the Board Revenue

Assessment will be applied to the customer's share of the PJM zonal capacity obligation.

c. BGS Reconciliation Charge

This is the BGS Reconciliation Charge for the BGS-CIEP service as explained in

the Accounting and Cost Recovery section of this Addendum.

d. CIEP Standby Fee

For the period June 1, 2022 through May 31, 2023, the EDCs will pay each BGS-CIEP supplier a CIEP Standby Charge equal to $0.000150 per kWh times their pro-rata share of the total energy usage measured at the meters of all of ACE’s BGS-CIEP eligible customers. The CIEP

Standby Fee is a delivery charge that is applicable to all customers having BGS-CIEP as their default supply service. This includes all customers served on Rate Schedules TGS, all customers served on Rate Schedules MGS Secondary, MGS Secondary Electric Vehicle Charging, MGS

Primary, AGS Secondary, and AGS Primary with a peak load share of 500 kW or greater, and all customers on Rate Schedules MGS Secondary, MGS Secondary Electric Vehicle Charging, MGS

Primary, AGS Secondary, and AGS Primary with a peak load share of less than 500 kW that have

elected the BGS-CIEP default supply option. Any under- or over-recovery of the CIEP Standby

Fee will continue to be subject to deferred accounting.

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ACE Company-Specific Addendum

E. BGS RATE DESIGN METHODOLOGY

1. ACE BGS-RSCP Pricing Spreadsheet

The resulting charge for each BGS-RSCP rate element (i.e., Rate RS summer charge, winter charge, etc.) for the non-hourly BGS-RSCP supply service will be based on factors applied to the tranche-weighted average of the BGS-RSCP winning bid prices adjusted for the seasonal payment factors. The rate class specific factors have been developed based on the ratios of the estimated underlying market costs of each rate element (for each rate class) to the overall BGS-

RSCP cost. The tables included in Attachment 2 and described below present all of the input data, intermediate calculations, and the final results in the calculation of these factors.

Table No. 1 (% Usage During PJM On-Peak Period) contains the percentage of on-peak load, by month, for each applicable Rate Schedule. The on-peak period as used in this table

(referred to as PJM periods) is defined as the 16-hour period from 7 A.M. to 11 P.M., Monday through Friday. All remaining weekday hours and all hours on weekends and holidays recognized by the National Electric Reliability Council (also known as NERC) are considered the off-peak period. This is consistent with the time periods used in the forwards market for trading of bulk power. The values in this table for each month are based on the most recent available settlement data for current ACE customers.

Table No. 2 (% Usage During ACE On-Peak Billing Period) contains the percentage of on- peak load, by month, for each applicable Rate Schedule based on the definitions of time periods as contained in ACE’s delivery Rate Schedules. These percentages are based on usage history for the RS TOU BGS customers for the most recent period.

Table No. 3 (Class Usage @ Customer) contains the billing month sales forecasted for the period of June 2022 through May 2023, with migration adjustments. The values in Table No. 3 will be updated in January 2022 to better reflect forecasts for the June 1st delivery year.

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ACE Company-Specific Addendum

Table No. 4 (Forward Prices – Energy Only @ Bulk System) contains the forward prices for energy, by time period and month, for the BGS analysis period. These values are the energy on- peak forwards as of June 1, 2021, for the PJM West trading hub for the period of June

2022 to May 2023, as utilized in BGS market-to-market calculations, and the historical ratio of actual off-peak to on-peak PJM LMPs for the prior summer and winter periods. An adjustment of the forward prices contained in Table No. 4 must be made to correct for the pricing differential between the PJM West trading hub and the ACE zone where the BGS supply will be utilized.

Table No. 5 (Zone-Hub Basis Differential) contains an estimate of the average zone-hub basis differential factors, by month and time period, which, when multiplied by the prices at the

PJM West trading hub, will result in costs for power delivered into the ACE zone.

Table No. 6 (Losses) contains the factors utilized for average system losses by Rate

Schedule and voltage level. Loss factors are developed by including losses at the 500kV transmission level as well as losses at lower transmission and distribution voltage levels currently approved for use by the Board.

Table No. 7 (Summary of Average BGS Energy Unit Costs @ Customer – PJM Time

Periods) is the calculation of the energy costs by rate, time period and season. These values are the seasonal and time period average costs per Megawatt hour (“MWh”) as measured at the customer billing meter (from Table No. 3), based on the forwards prices (from Table No. 4), corrected for zone-hub basis differential (from Table No. 5), losses (from Table No. 6), and monthly time period weights (from Table No. 1). These average costs do not include the costs associated with Ancillary Services, RPS compliance or Generation Obligation costs, which will be considered in subsequent calculations.

21

ACE Company-Specific Addendum

Table No. 8 (Summary of Average BGS Energy Costs @ Customer – PJM Time Periods)

indicates the total value, in thousands of dollars, of the average BGS energy costs. These are the results of the multiplication of the unit costs from Table No. 7, the monthly time period weights from Table No. 1, and the total sales to customers from Table No. 3. Since the end result of these calculations are to be utilized in the development of retail BGS rates, the rates utilizing time of day pricing must be developed based upon the time periods as defined for billing.

Table No. 9 (Summary of Average BGS Energy Unit Costs @ Customer – ACE Time

Periods) shows the result of the corrections for the RS TOU BGS rate. These values are calculated based on the assumption that the MWhs included in the PJM on-peak time period and not included in the ACE on-peak time periods are at the average of the on- and off-peak PJM prices.

Table No. 10 (Generation Obligations and Costs and Other Adjustments) includes the values necessary for the inclusion of the costs of the Generation Capacity obligations. The top portion of Table No. 10 shows the total generation obligations with a migration adjustment, by applicable Rate Schedule, that are currently being utilized in the year 2021. Table No. 10 will be updated in January 2022, similar to Table No. 3. The middle portion of this table shows the number of summer and winter days and months that are used in this analysis. The bottom portion of this table shows the seasonally differentiated average market price of generation capacity, using the relevant RPM auction result for Delivery Year 2022/2023, the

Capacity Proxy Price for Delivery Year 2023/2024, and the Capacity Proxy Price for Delivery

Year 2024/2025. The Capacity Proxy Price will be replaced with the Zonal Capacity Prices, which are the prices paid by BGS-RSCP Suppliers for Capacity for the 2023/2024 and the 2024/2025

Delivery Years when available as may be determined through the RPM or its successor or otherwise.

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ACE Company-Specific Addendum

Table No. 11 (Ancillary Services and RPS) contains an estimate of the effects of the costs of ancillary services and RPS. The values of $2.00 per MWh and $15.26 per MWh are used, respectively. Since the actual costs are a complex combination of many factors, an estimate of the overall annual average value, expressed on a dollar per MWh basis, is used as a reasonable and practical alternative.

Table No. 12 (Summary of Obligation Costs Expressed as $/MWh @ Customer) shows the result of the allocation of the generation costs, on a per MWh basis, to all Rate Schedules. For

RS TOU BGS, the per MWh Generation Capacity Obligation Costs are based on the on-peak usage only.

Table No. 13 (Summary of BGS Unit Costs @ Customer) is the result of the inclusion of the generation capacity, Ancillary Services, and RPS costs to the energy only costs shown in Table

No. 9. This table shows the total estimated costs for BGS, based on the assumptions utilized in the above tables, and the average per unit cost, as measured at the customer meters or the bulk system meters.

Table No. 14 (Ratio of BGS Unit Costs @ Customer to Average Cost @ transmission nodes) indicates the ratio of the individual rate element costs from Table No. 13 to the overall cost as measured at the transmission nodes, plus constants, where applicable.

Table No. 15 (Summary of Total BGS Costs by Season) shows the calculation of the total

BGS Costs, utilizing the total customer usage from Table No. 3 and the BGS unit costs from Table

No. 13. The lower left portion of the table indicates the relative percentage of total costs by season for all Rate Schedules, while the center shows the calculation of the overall average seasonal unit costs on a dollar per MWh basis. The ratio of these overall average seasonal costs to the overall total cost, shown in the lower right-hand portion of Table No. 15, are the seasonal

23

ACE Company-Specific Addendum

payment ratios upon which payments to the winning bidders are based. The final section

summarizes some of the most important assumptions utilized in the above calculations.

Table No. 16 (Retail Rates Charged to BGS-RSCP Customers), shows the calculation of

retail rates to be charged to the BGS-RSCP customers for their BGS services. This table utilizes

the information computed in Table No. 14 (Ratio of BGS Unit Costs) and applies the applicable

ratios for each rate class to the BGS average price which, in turn, is based on the weighted average

winning bids . The upper left portion of this table provides the BGS average price.

Table No. 17 (Retail Rates Charged to BGS-RSCP Customers Including Revenue

Assessment and SUT), shows the BGS-RSCP customer rates inclusive of the BPU and Division of Rate Counsel revenue assessments, as well as SUT. This table utilizes the information

provided in Table No. 16 and applies the applicable revenue assessment factor and SUT rate

to derive the tax effected BGS-RSCP customer’s rates.

The second spreadsheet used in the calculation of the final BGS-RSCP rates is included as

Attachment 3 and is titled “Calculation of June 2022 to May 2023 BGS-RSCP Rates.” The tables in this spreadsheet calculate the weighted average winning bid price and convert it into the final BGS-RSCP rates that are charged to customers. An explanation of each of the six tables, labeled as Tables A through F, is as follows:

Table A (Auction Results) contains the results of the 2020/2021 BGS auction, reduced by the assumed transmission price in that bid, arrived at by the method shown in Attachment 5 –

Development of Assumed Transmission Price in Bid, the results of the 2021/2022 BGS auction, as well as the results of the current auction. The Capacity Proxy Price True Up cost in

$ per MWh will be used to reflect the impact of payments made pursuant to the Supplements executed by BGS Suppliers in February 2020 and February 2021. Upon conclusion of the Third

24

ACE Company-Specific Addendum

Incremental RPM Auction through the RPM or its successor or otherwise, the price paid by BGS-

RSCP Suppliers for Capacity in the Company’s PJM Zone will be known. The Capacity Proxy

Price True-Up will then be determined by the price difference between the price paid by BGS-

RSCP Suppliers for Capacity in the Company’s PJM Zone and the Capacity Proxy Price for the

2022/2023 Delivery Year. The value of the recently concluded BRA in June of 2021 is used as an approximation of the price paid by BGS-RSCP Suppliers for Capacity in the Company’s PJM Zone

for 2022/2023.. From these values, the weighted average annual bid price (shown on line 13) is

calculated. All of the formulas used in this table are shown in the right-hand column of this table,

under the heading “Notes.”

Table B (Ratio of BGS Unit Costs @ Customer to Average Cost @ transmission nodes)

is a repeat of the values shown in Table No. 14 from Attachment 2, the bid factors calculated

based on current market conditions.

Table C (Preliminary Resulting BGS Rates) contains the preliminary customer BGS-

RSCP rates as the product of the weighted average bid price (from Table A) and the Bid Factors

from Table B.

Table D (Revenue Recovery Calculations) contains a comparison of the total anticipated

rate revenue billed to customers based on the preliminary BGS-RSCP rates developed in Table C

and the anticipated total season payments to BGS suppliers, based on the data in Table A. The

calculation of the kWh Rate Adjustment Factors are also provided in this table, which are equal

to the seasonal dollar differences between the anticipated billed revenue and supplier payments,

divided by the total anticipated seasonal billed BGS-RSCP energy-related charges.

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ACE Company-Specific Addendum

Table E (Final Resulting BGS Rates) contains the final adjusted BGS-RSCP rates, which

are equal to the preliminary BGS–RSCP rates shown in Table C, times the seasonal kWh Rate

Adjustment Factors that were developed in Table D.

Table F (Spreadsheet Error Checking) contains a comparison of the total anticipated rate revenue billed to customers based on the final BGS-RSCP rates developed in Table E, and the anticipated total season payments to BGS suppliers, based on the data in Table A.

F. CONCLUSION

In connection with the approval of this filing, the Company respectfully requests that the Board

determine as follows:

1. it is necessary and in the public interest for the electric public utilities to secure service for

the BGS-RSCP and BGS-CIEP customers, as approved herein, for the period June 1, 2022

to May 31, 2025;

2. the Company’s proposed accounting for BGS is approved for purposes of accounting and

BGS cost recovery;

3. the proposed BGS Contingency Plan is approved, and there will exist a presumption of

prudence with respect to the BGS Auction Plan method and the costs incurred for BGS

service under the Auction Plan and the related Contingency Plan; and

4. the Company’s Rate Design Methodology and Tariff Sheets are approved.

26

Attachment 1

Attachment 1 Page 1 of 3

ATLANTIC CITY ELECTRIC COMPANY BPU NJ No. 11 Electric Service - Section IV Revised Sheet Replaces Revised Sheet No. 60 RIDER (BGS) Basic Generation Service (BGS) Basic Generation Service (BGS) will be arranged for any customer taking service under Electric Rate Schedules RS, MGS Secondary, MGS-SEVC, MGS Primary, AGS Secondary, AGS Primary, TGS, DDC, SPL, and CSL who has not notified the Company of an Alternative Electric Supplier choice. BGS is also available to customers whose arrangements with Alternative Electric Suppliers have terminated for any reason, including nonpayment.

BGS is offered under two different terms of service; Basic Generation Service-Residential Small Commercial Pricing (BGS-RSCP) and Basic Generation Service -Commercial and Industrial Energy Pricing (BGS-CIEP). BGS-RSCP is offered to customers on Rate Schedules RS, DDC, SPL and CSL. BGS-RSCP is also offered to customers on Rate Schedules MGS Secondary, MGS-SEVC, MGS Primary, AGS Secondary, AGS Primary with an annual peak load share (“PLS”) for generation capacity of less than 500 kW as of November 1 or each year. Additionally, BGS customers on Rate Schedule RS have the option of taking BGS-RSCP on a time of use basis.

BGS customers on Rate Schedule TGS and BGS customers on Rate Schedules MGS Secondary, MGS-SEVC, MGS Primary, AGS Secondary or AGS Primary with a PLS for generation capacity equal to or greater than 500 kW as of November 1 of each year are required to take service under BGS-CIEP.

Customers on Rate Schedules MGS Secondary, MGS-SEVC, MGS Primary, AGS Secondary or AGS Primary with a PLS of less than 500 kW, have the option of taking either BGS-RSCP or BGS-CIEP service. Customers who elect BGS-CIEP must notify the Company of their selection no later than the second working day of January of the year they wish to begin BGS-CIEP service. Such election will be effective on June 1 of that year and remain as the customer’s default supply for the following twelve months. Customers electing BGS-CIEP as their default supply in a prior procurement period and who are otherwise eligible to return to BGS-RSCP may return to BGS RSCP by notifying the Company no later than the second working day of January of the year that they wish to return to BGS- RSCP service. Such election shall be effective on June 1 of that year.

BGS-RSCP Supply Charges SUMMER WINTER ($/kWh): Rate Schedule June Through September October Through May RS $ x.xxxxxx <=750 kwhs summer $ x.xxxxxx > 750 kwh summer $ x.xxxxxx RS TOU BGS Option On Peak (See Note 1) $ x.xxxxxx $ x.xxxxxx Off Peak (See Note 1) $ x.xxxxxx $ x.xxxxxx MGS-Secondary and MGS-SEVC $ x.xxxxxx $ x.xxxxxx MGS-Primary $ x.xxxxxx $ x.xxxxxx AGS-Secondary $ x.xxxxxx $ x.xxxxxx AGS-Primary $ x.xxxxxx $ x.xxxxxx DDC $ x.xxxxxx $ x.xxxxxx SPL/CSL $ x.xxxxxx $ x.xxxxxx Note 1: On Peak hours are considered to be 8:00 AM to 8:00 PM, Monday through Friday.

The above Basic Generation Service Energy Charges reflect costs for Energy, Generation Capacity, Ancillary Services and Administrative Charges pursuant to N.J.S.A. 48:2-60 plus New Jersey Sales and Use Tax as set forth in Rider SUT.

Date of Issue: Effective Date:

Issued by:

Attachment 1 Page 2 of 3

ATLANTIC CITY ELECTRIC COMPANY BPU NJ No. 11 Electric Service - Section IV Revised Sheet Replaces Revised Sheet No. 60a RIDER (BGS) continued Basic Generation Service (BGS) BGS Reconciliation Charge ($/kWh): The above charge shall recover the difference between the monthly amount paid to Basic Generation Service (BGS) suppliers and the total revenue from customers for BGS for the preceding months for the applicable BGS supply. These charges include New Jersey Sales and Use Tax as set forth in Rider SUT and are changed on June 1 and October 1 of each year. Rate Schedule Charge ($ per kWh) RS $ (0.003932) MGS Secondary, MGS-SEVC, AGS Secondary, SPL/CSL, DDC $ (0.003932) MGS Primary, AGS Primary $ (0.003829) BGS-CIEP

Energy Charges BGS Energy Charges for Rate Schedule TGS, AGS and MGS customers with a Peak Load Share (PLS) of 500 kW or more, and AGS and MGS customers with a PLS of less than 500 kW who have elected BGS-CIEP are hourly and are provided at the real time PJM Load Weighted Average Residual Metered Load Aggregate Locational Marginal Prices for the Atlantic Electric Transmission Zone, adjusted for losses, plus administrative charges pursuant to N.J.S.A. 48:2-60 and New Jersey Sales and Use Tax as set forth in Rider SUT. Generation Capacity Obligation Charge Summer Winter Charge per kilowatt of Generation Obligation ($ per kW per day) $x.xxxxxx $x.xxxxxx

This charge is equal to the winning bid price from the BGS-CIEP default service auction plus administrative charges pursuant to N.J.S.A. 48:2-60 and New Jersey Sales and Use Tax as set forth in Rider SUT. The above charge shall be applied to each customer’s annual peak load share (“PLS”) for generation capacity, adjusted for the applicable PJM-determined Zonal Scaling Factor and the applicable PJM-determined capacity reserve margin factor, on a daily basis for each day in each customer's respective billing cycle. Ancillary Service Charge Charge ($ per kWh) Service taken at Secondary Voltage $ x.xxxxxx Service taken at Primary Voltage $ x.xxxxxx Service taken at Sub-Transmission Voltage $ x.xxxxxx Service taken at Transmission Voltage $ x.xxxxxx

This charge represents the average annual cost of Ancillary Services in the Atlantic Electric Transmission zone adjusted for losses, plus administrative charges pursuant to N.J.S.A. 48:2-60 and New Jersey Sales and Use Tax as set forth in Rider SUT. BGS Reconciliation Charge: Charge ($ per kWh) Service taken at Secondary Voltage $ 0.001944 Service taken at Primary Voltage $ 0.001893 Service taken at Sub-Transmission Voltage $ 0.001871 Service taken at Transmission Voltage $ 0.001853

The above charge shall recover the difference between the monthly amount paid to Basic Generation Service (BGS) suppliers and the total revenue from customers for BGS for the preceding months for the applicable BGS supply. These charges include administrative charges pursuant to N.J.S.A. 48:2-60 and New Jersey Sales and Use Tax as set forth in Rider SUT and are changed on June 1 and October 1 of each year.

Date of Issue: Effective Date:

Issued by:

Attachment 1 Page 3 of 3 ATLANTIC CITY ELECTRIC COMPANY BPU NJ No. 11 Electric Service - Section IV Revised Sheet Replaces Revised Sheet No. 60b RIDER (BGS) continued Basic Generation Service (BGS)

CIEP Standby Fee $x.xxxxxx per kWh This charge recovers the costs associated with the winning BGS-CIEP bidders maintaining the availability of the hourly priced default electric supply service plus administrative charges pursuant to N.J.S.A. 48:2-60 and New Jersey Sales and Use Tax as set forth in Rider SUT. This charge is assessed on all kWhs delivered to all CIEP- eligible customers on Rate Schedules MGS Secondary, MGS-SEVC, MGS Primary, AGS Secondary, AGS Primary or TGS.

Transmission Enhancement Charge This charge reflects Transmission Enhancement Charges (“TECs”), implemented to compensate transmission owners for the annual transmission revenue requirements for “Required Transmission Enhancements” (as defined in Schedule 12 of the PJM OATT) that are requested by PJM for reliability or economic purposes and approved by the Federal Energy Regulatory Commission (FERC). The TEC charge (in $ per kWh by Rate Schedule), including administrative charges pursuant to N.J.S.A. 48:2-60 and New Jersey Sales and Use Tax as set forth in Rider SUT, is delineated in the following table. Rate Class

MGS Secondary And MGS- MGS AGS AGS SPL/ RS SEVC Primary Secondary Primary TGS CSL DDC

VEPCo 0.000371 0.000269 0.000294 0.000189 0.000146 0.000134 - 0.000117

- TrAILCo 0.000338 0.000245 0.000269 0.000172 0.000133 0.000122 0.000107

PSE&G 0.000669 0.000485 0.000532 0.000340 0.000263 0.000241 - 0.000211

PATH 0.000077 0.000057 0.000062 0.000039 0.000031 0.000028 - 0.000025

- PPL 0.000118 0.000085 0.000094 0.000060 0.000047 0.000043 0.000037

- PECO 0.000134 0.000097 0.000107 0.000068 0.000053 0.000048 0.000043

- Pepco 0.000025 0.000018 0.000019 0.000013 0.000010 0.000009 0.000007

MAIT 0.000034 0.000025 0.000027 0.000017 0.000014 0.000013 - 0.000011

JCP&L 0.000003 0.000002 0.000002 0.000002 0.000001 0.000001 - 0.000001

EL05-121 0.000019 0.000014 0.000016 0.000010 0.000007 0.000007 - 0.000006

Delmarva 0.000007 0.000005 0.000005 0.000003 0.000003 0.000002 - 0.000002

BG&E 0.000029 0.000021 0.000023 0.000015 0.000012 0.000011 - 0.000010

AEP-East 0.000075 0.000054 0.000059 0.000038 0.000029 0.000027 - 0.000023

Silver Run 0.000317 0.000230 0.000253 0.000162 0.000125 0.000115 - 0.000100

NIPSCO 0.000003 0.000002 0.000002 0.000002 0.000001 0.000001 - 0.000001

CW Edison 0.000001 0.000001 0.000001 - - - - -

ER18-680 & 0.000084 0.000061 0.000067 0.000043 0.000033 0.000030 - 0.000027 Form 715 Total 0.002304 0.001671 0.001832 0.001173 0.000908 0.000832 - 0.000728

Date of Issue: Effective Date:

Issued by:

Attachment 2

Atlantic City Electric Company Attachment 2 Development of BGS Rates Page 1 of 5 June 2022 - May 2023

Table #1 % usage during PJM On-Peak period On-Peak periods defined as the 16 hr PJM Trading period, adj for NERC holidays (data rounded to nearest %) RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC

January 50.34% 50.42% 57.98% 54.16% 56.98% 52.25% 36.65% 50.12% February 47.30% 47.33% 56.48% 53.20% 55.36% 51.83% 32.87% 49.09% March 49.26% 49.31% 56.94% 52.57% 56.47% 52.65% 29.64% 50.28% April 51.56% 51.60% 57.78% 51.08% 55.49% 52.43% 25.77% 51.31% May 48.21% 48.50% 47.16% 44.98% 48.60% 45.04% 18.27% 43.53% June 51.97% 52.01% 56.49% 53.10% 57.15% 52.48% 20.23% 50.91% July 56.82% 57.14% 60.66% 54.96% 59.05% 54.65% 20.16% 52.51% August 52.64% 52.84% 55.64% 50.93% 53.94% 49.99% 22.42% 48.11% September 53.78% 53.72% 56.79% 55.58% 57.61% 53.24% 28.18% 49.98% October 51.48% 51.47% 58.26% 54.23% 57.69% 53.79% 33.33% 50.60% November 48.04% 48.05% 51.87% 52.15% 54.97% 50.15% 34.58% 47.22% December 49.82% 49.80% 61.81% 53.62% 57.60% 52.84% 37.91% 50.81%

Table #2 % Usage During ACECO On-Peak Billing Period

RS TOU - BGS

January 36.26% February 33.10% March 34.38% April 36.70% May 35.65% June 38.68% July 44.10% August 41.10% September 40.52% October 37.09% November 35.60% December 35.88%

Table #3 Class Usage @ customer calendar month sales forecasted for period in MWh RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC Total

Jan-23 342,172 223 67,927 1,237 69,548 4,630 4,787 827 491,350 Feb-23 297,800 200 70,657 1,066 78,089 3,800 4,876 852 457,339 Mar-23 273,814 183 64,144 1,436 62,120 5,297 4,239 783 412,015 Apr-23 236,632 153 65,559 1,415 66,729 4,452 4,197 795 379,932 May-23 204,838 125 59,198 925 63,683 2,984 3,470 715 335,939 Jun-22 272,568 161 72,083 1,419 80,004 4,480 3,680 875 435,269 Jul-22 412,713 242 80,671 1,509 76,086 5,237 3,785 989 581,232 Aug-22 474,911 280 87,452 1,235 87,125 6,933 4,235 1,075 663,246 Sep-22 404,013 239 88,140 1,458 85,935 4,810 4,478 1,077 590,150 Oct-22 248,313 147 62,606 947 65,750 2,922 3,645 771 385,102 Nov-22 214,630 131 65,159 928 60,203 5,865 4,426 803 352,146 Dec-22 263,714 169 64,291 1,338 65,006 3,353 4,569 783 403,223 Total 3,646,119 2,252 847,887 14,911 860,276 54,763 50,386 10,348 5,486,943 Atlantic City Electric Company Attachment 2 Development of BGS Rates Page 2 of 5 June 2022 - May 2023

Table #4 Forwards Prices - Energy Only @ bulk system Table #5 Zone-Hub Basis Differential 'Based on 3 Year Average ($/MWH) Off/On Pk On-Peak LMP ratio Off-Peak On-Peak Off-Peak Jan-23 47.45 0.762 36.16 88% 92% Feb-23 44.75 0.762 34.10 88% 92% Mar-23 32.10 0.762 24.46 88% 92% Apr-23 29.10 0.762 22.18 88% 92% May-23 29.00 0.762 22.10 88% 92% Jun-22 30.95 0.671 20.76 87% 90% Jul-22 37.20 0.671 24.95 87% 90% Aug-22 34.70 0.671 23.27 87% 90% Sep-22 32.30 0.671 21.66 87% 90% Oct-22 30.50 0.762 23.24 88% 92% Nov-22 30.90 0.762 23.55 88% 92% Dec-22 34.50 0.762 26.29 88% 92%

Table #6 Losses RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC Delivery Loss Factor 6.6720% 6.6720% 6.6720% 4.1641% 6.6720% 4.1641% 6.6720% 6.6720% Loss Factors + EHV Losses = 7.0688% 7.0688% 7.0688% 4.5715% 7.0688% 4.5715% 7.0688% 7.0688% Expansion Factor = 1.07606 1.07606 1.07606 1.04790 1.07606 1.04790 1.07606 1.07606

Marginal Loss Factor (w/ EHV Losses) = 1.7840% 1.7840% 1.7840% 1.7840% 1.7840% 1.7840% 1.7840% 1.7840% Loss Factor w/o Marginal Loss = 5.3808% 5.3808% 5.3808% 2.8381% 5.3808% 2.8381% 5.3808% 5.3808% Expansion Factor w/o Marginal Loss = 1.05687 1.05687 1.05687 1.02921 1.05687 1.02921 1.05687 1.05687

Table #7 Summary of Average BGS Energy Unit Costs @ customer - PJM Time Periods based on Forwards @ PJM West - corrected for congestion & losses in $/MWh RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC

Summer - all hrs$ 27.51 $ 27.51 $ 27.65 $ 26.54 $ 27.51 $ 26.55 $ 24.19 $ 26.96 On Peak$ 32.12 $ 32.12 $ 31.89 $ 30.97 $ 31.75 $ 31.15 $ 31.65 $ 31.87 Off Peak$ 22.10 $ 22.10 $ 21.95 $ 21.39 $ 21.92 $ 21.50 $ 21.97 $ 21.99

Winter - all hrs$ 30.41 $ 30.55 $ 30.24 $ 29.07 $ 30.30 $ 29.01 $ 28.92 $ 29.76 On Peak$ 33.73 $ 33.88 $ 33.24 $ 32.23 $ 33.31 $ 32.14 $ 34.00 $ 33.14 Off Peak$ 27.15 $ 27.28 $ 26.41 $ 25.62 $ 26.57 $ 25.69 $ 26.57 $ 26.50

Annual$ 29.16 $ 29.31 $ 29.24 $ 28.11 $ 29.23 $ 28.05 $ 27.40 $ 28.67

System Average Cost @ customer - (limited to classes shown above) =$ 29.16

Table #8 Summary of Average BGS Energy Costs @ customer - PJM Time Periods based on Forwards prices corrected for congestion & losses in $1000 RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC

Summer - all hrs$ 43,026 $ 25 $ 9,079 $ 149 $ 9,054 $ 570 $ 391 $ 108 PJM on pk$ 27,093 $ 16 $ 6,007 $ 94 $ 5,942 $ 350 $ 118 $ 64 PJM off pk$ 15,933 $ 9 $ 3,072 $ 56 $ 3,112 $ 220 $ 274 $ 44

Winter - all hrs$ 63,309 $ 41 $ 15,713 $ 270 $ 16,096 $ 966 $ 989 $ 188 PJM on pk$ 34,776 $ 22 $ 9,692 $ 156 $ 9,806 $ 551 $ 367 $ 103 PJM off pk$ 28,533 $ 18 $ 6,020 $ 114 $ 6,290 $ 415 $ 622 $ 85

Annual$ 106,335 $ 66 $ 24,792 $ 419 $ 25,150 $ 1,536 $ 1,381 $ 297

System Total$ 159,975 Atlantic City Electric Company Attachment 2 Development of BGS Rates Page 3 of 5 June 2022 - May 2023

Table #9 Summary of Average BGS Energy Unit Costs @ customer - ACECO Time Periods based on Forwards prices corrected for congestion & losses - ACECO billing time periods in $/MWh RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC

Summer - all hrs$ 27.51 $ 27.51 $ 27.65 $ 26.54 $ 27.51 $ 26.55 $ 24.19 $ 26.96 ACECO On pk$ 33.67 ACECO Off pk$ 23.18

Winter - all hrs$ 30.41 $ 30.55 $ 30.24 $ 29.07 $ 30.30 $ 29.01 $ 28.92 $ 29.76 ACECO On pk$ 35.19 ACECO Off pk$ 28.00

Annual Average$ 29.16 $ 29.31 $ 29.24 $ 28.11 $ 29.23 $ 28.05 $ 27.40 $ 28.67 System Average$ 29.16

Table #10 Generation Obligations and Costs and Other Adjustments obligations - values effective June 2021; costs are market estimates in MW RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC Total

Gen Load - MW 1,304.8 0.6 246.0 3.2 176.6 8.8 0.0 1.3 1,741.2 Gen Obl - MW 1,528.1 0.7 288.1 3.8 206.8 10.3 0.0 1.5 2,039.2

# of Months and Days used in this analysis # of summer days = 122 # of summer months = 4 # of winter days = 243 # of winter months = 8 total # months = 12

Base Generation Capacity Cost Capacity Summer $101.28 $/MW/day Summer Total$ 25,196,877 Winter $101.28 $/MW/day Winter Total $ 50,187,222 Annual Total$ 75,384,099

Residential Inversion Determination ------Rate RS ------Charges % usage SUM 'First 750 KWh 1,157,623,154 Block 1 (0-750 kWh/m) 5.480200 61.20% SUM '> 750 KWh 733,772,796 Block 2 (>750 kWh/m) 6.345400 38.80% Calculated inversion = 0.865200 WIN 2,160,202,281 4,051,598,231

Table #11 Ancillary Services & Renewable Power Cost (forecasted overall annual average) Ancillary Services $ 2.00 Renewable Power Cost $ 15.26 Total Ancillary Services & Renewable Power Costs $ 17.26

Table #12 Summary of Obligation Costs expressed as $/MWh @ customer RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC Generation Obl - per annual MWh$ 15.49 $ 30.27 $ 12.56 $ 9.35 $ 8.89 $ 6.94 $ - $ 5.44 recovery per summer MWh$ 12.07 $ 22.66 $ 10.84 $ 8.29 $ 7.76 $ 5.92 $ - $ 4.69 recovery per winter MWh$ 18.06 $ 36.42 $ 13.65 $ 9.99 $ 9.58 $ 7.60 $ - $ 5.92 Atlantic City Electric Company Attachment 2 Development of BGS Rates Page 4 of 5 June 2022 - May 2023

Table #13 Summary of BGS Unit Costs @ customer Includes energy, Generation capacity obligations, Ancillary Services, and Renewable Power Costs - unadjusted for billing vs. PJM time period differences. in $/MWh RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC

Summer - all hrs$ 58.15 $ 68.74 $ 57.07 $ 52.92 $ 53.84 $ 50.56 $ 42.77 $ 50.22 On-Peak $ 74.89 Off-Peak$ 41.76 Block 1 (0-750 kWh/m)$ 54.79 Block 2 (>750 kWh/m)$ 63.45

Winter - all hrs$ 67.05 $ 85.55 $ 62.46 $ 57.15 $ 58.46 $ 54.70 $ 47.49 $ 54.26 On-Peak $ 90.18 Off-Peak$ 46.57 Annual$ 63.23 $ 59.35 $ 60.37 $ 55.55 $ 56.69 $ 53.08 $ 45.98 $ 52.69

Grand Total Cost in $1000 =$ 337,234

Average cost for rates shown (@ customer) = $ 61.46 Average costs for rates shown (@ transmission nodes) = $ 58.17

Table #14 Ratio of BGS Unit Costs @ customer to Average Cost @ transmission nodes (rounded to 3 decimal places) Includes energy, Generation capacity obligations, Ancillary Services, and Renewable Power Costs - unadjusted for billing vs. PJM time period differences.

RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC

Summer - all hrs 1.182 0.981 0.910 0.926 0.869 0.735 0.863 On-Peak 1.287 Off-Peak 0.718 All usage Multiplier 1.000 Constant $ (3.36) for Block 1 (0-750 kWh/m) usage Constant $ 5.30 for Block 2 (>750 kWh/m) usage

Winter - all hrs 1.153 1.471 1.074 0.982 1.005 0.940 0.816 0.933 On-Peak 1.550 Off-Peak 0.801 Annual 1.087 1.020 1.038 0.955 0.975 0.912 0.790 0.906

Table #15 Summary of Total BGS Costs by Season

RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC Total Costs by Rate - in $1000 Summer$ 90,959 $ 63 $ 18,737 $ 297 $ 17,722 $ 1,085 $ 692 $ 202 Winter$ 139,584 $ 114 $ 32,452 $ 531 $ 31,049 $ 1,822 $ 1,625 $ 344 Total$ 230,543 $ 177 $ 51,189 $ 828 $ 48,771 $ 2,907 $ 2,317 $ 545

% of Annual Total $ by Rate Summer 39% 36% 37% 36% 36% 37% 30% 37% Winter 61% 64% 63% 64% 64% 63% 70% 63%

Total Costs - in $1000 Summer$ 129,758 Winter$ 207,520 Total$ 337,277

% of Annual Total $ If total $ were split on a per MWh basis (on bulk system MWhs): Summer 38%$ 54.11 per MWh @ trans nodes Ratio to BGS Cost >>> Summer 1.0000 Winter 62%$ 61.06 per MWh @ trans nodes (rounded to 4 decimal places) Winter 1.0000

Assumptions: Gen Cost = $101.28 per MW-day summer = $101.28 per MW-day winter Ancillary Services =$ 2.00 per MWH Renewable Power Cost =$ 15.26 per MWH Energy Prices = Quotes for the period June 1, 2022 to May 31, 2023 - corrected for hub-zone basis differential. Usage patterns = forecasted energy use by class, on/off % from class load profiles Obligations = class totals as of June 2021 Losses = existing approved loss factors PJM Time Periods = PJM trading time periods - 7 AM to 11 PM weekdays, local time, x NERC holidays - New Year's, Memorial, 4th of July, Labor Day, Thanksgiving & Christmas Atlantic City Electric Company Attachment 2 Development of BGS Rates Page 5 of 5 June 2022 - May 2023

Table #16 Retail Rates Charged to BGS RSCP (Previously "FP") Customers Includes energy, Generation Obligations, Ancillary Services, and Renewable Power Costs in $/MWh

BGS Avg. Price >>>>>>>>>>> $ 60.158

RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC Summer - all hrs$ 76.431 $ 63.434 $ 58.843 $ 59.878 $ 56.192 $ 47.527 $ 55.804 On-Peak $ 83.221 Off-Peak$ 46.428 Block 1 (0-750 kWh/m)$ 61.055 Block 2 (>750 kWh/m)$ 70.355 Winter - all hrs$ 66.072 $ 84.295 $ 61.545 $ 56.273 $ 57.591 $ 53.866 $ 46.761 $ 53.465 On-Peak $ 88.822 Off-Peak$ 45.901 Annual$ 65.392 $ 61.361 $ 62.444 $ 57.451 $ 58.654 $ 54.864 $ 47.525 $ 54.503

Table #17 Retail Rates Charged to BGS RSCP Customers including Revenue Assessment and SUT Includes energy, Generation Obligations, Ancillary Services, and Renewable Power Costs in $/kWh Revenue Assessment Factor 1.002695547 (BPU, RC Assessments)

RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC Summer - all hrs $ 0.067819 $ 0.062910 $ 0.064017 $ 0.060076 $ 0.050812 $ 0.059661 On-Peak $ 0.088973 Off-Peak$ 0.049637 Block 1 (0-750 kWh/m)$ 0.065275 Block 2 (>750 kWh/m)$ 0.075218 Winter - all hrs$ 0.070640 $ 0.065800 $ 0.060163 $ 0.061572 $ 0.057590 $ 0.049993 $ 0.057161 On-Peak $ 0.094962 Off-Peak$ 0.049074 Annual$ 0.069912 $ 0.065603 $ 0.066760 $ 0.061422 $ 0.062708 $ 0.058657 $ 0.050810 $ 0.058271

Attachment 3

Atlantic City Electric Company Attachment 3 Development of BGS Rates Page 1 of 4 June 2022 - May 2023

Atlantic City Electric Company Calculation of June 2022 to May 2023 BGS-RSCP Rates based on results of February 2022 BGS RSCP Auction

Table A Auction Results remaining remaining portion of 36 portion of 36 month bid - month bid - 36 month bid - line # Payment Identifier >> 2020/21 filing 2021/22 filing 2022/23 filing Notes:

1 Winning Bid - in $/MWh $ 82.69 $ 64.20 $ 64.20 winning Bids 1A Capacity Proxy Price True-Up - in $/MWh $ (5.95) $ (5.95) entered after 2022 BGS Auction 1B Transmission Price $ 18.45 asssumed transmission price in bid 1C Total - in $/Mwh $ 58.29 $ 58.25 $ 64.20 = line 1 + line 1A - line 1B

2 # of Tranches for Bid 877 from then current Bid 3 Total # of Tranches 22 22 22 from then current Bid

Payment Factors 4 Summer 1.0000 1.0000 1.0000 from then current Bid Factor Spreadsheet 5 Winter 1.0000 1.0000 1.0000 from then current Bid Factor Spreadsheet

Applicable Customer Usage @ bulk system - in MWh 6 Summer MWh 2,398,232 from current Bid Factor Spreadsheet 7 Winter MWh 3,398,812

Total Payment to Suppliers - in $1000 8 Summer$ 50,834 $ 44,449 $ 48,989 = ((1 - 1B) * (2)/(3) * (4) * (6)) + ((1A) * (2)/(3) * (6)) 9 Winter$ 72,042 $ 62,994 $ 69,428 = ((1 - 1B) * (2)/(3) * (5) * (7)) + ((1A) * (2)/(3) * (7)) 10 Total$ 122,876 $ 107,443 $ 118,418

Average Payment to Suppliers - in $/MWh 11 Summer$ 60.16 = sum(line 8) / (6) - rounded to 2 decimal places 12 Winter$ 60.16 = sum(line 9) / (7) - rounded to 2 decimal places

13 Total weighted average $ 60.16 <<< used in calculation of = sum(line 10) / [ (6) + (7)] Customer Rates rounded to 2 decimal places

Reconciliation of amounts - in $1000 14 Weighted avg * Total MWh =$ 348,739 = (13) * [(6)+(7)] / 1000 15 Total Payment to Suppliers =$ 348,737 = sum (line 10) 16 Difference =$ 2 = line (14) - line (15) Atlantic City Electric Company Attachment 3 Development of BGS Rates Page 2 of 4 June 2022 - May 2023

Atlantic City Electric Company Calculation of June 2022 to May 2023 BGS-RSCP Rates based on results of February 2022 BGS RSCP Auction

Table B Ratio of BGS Unit Costs @ customer to Average Cost @ transmission nodes from Table #14 of the bid factor spreadsheet --- round to 3 decimal places

includes energy, G obligations, Ancillary Services, and Renewable Power Cost - adjusted to billing time periods

RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC

Summer - all hrs 1.182 0.981 0.910 0.926 0.869 0.735 0.863 On-Peak 1.287 Off-Peak 0.718

All usage Multiplier 1.000 Constant (3.357) for Block 1 (0-750 kWh/m) usage Constant 5.295 for Block 2 (>750 kWh/m) usage

Winter - all hrs 1.153 1.471 1.074 0.982 1.005 0.940 0.816 0.933 On-Peak 1.550 Off-Peak 0.801

Annual - all hrs 1.087 1.020 1.038 0.955 0.975 0.912 0.790 0.906

Table C Preliminary Resulting BGS Rates (in cents per kWh) - equal to bid factors times weighted average bid price rounded to 4 decimal places

includes energy, G obligations, Ancillary Services, and Renewable Power Cost - adjusted to billing time periods

RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC

Summer - all hrs 7.1107 5.9015 5.4744 5.5706 5.2277 4.4216 5.1916 On-Peak 7.7423 Off-Peak 4.3193

for Block 1 (0-750 kWh/m) usage 5.6801 for Block 2 (>750 kWh/m) usage 6.5453

Winter - all hrs 6.9362 8.8492 6.4610 5.9075 6.0459 5.6549 4.9089 5.6127 On-Peak 9.3245 Off-Peak 4.8187 Atlantic City Electric Company Attachment 3 Development of BGS Rates Page 3 of 4 June 2022 - May 2023

Atlantic City Electric Company Calculation of June 2022 to May 2023 BGS-RSCP Rates based on results of February 2022 BGS RSCP Auction

Table D Revenue Recovery Calculations - Reconciliation of seasonal Customer Revenue and Supplier Payments, based on actual anticipated revenues and payments

RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC Total Rate Revenue - in $1000 Summer$ 94,099 $ 57 $ 19,377 $ 308 $ 18,336 $ 1,122 $ 715 $ 209 Winter$ 144,406 $ 94$ 33,568 $ 549 $ 32,111 $ 1,883 $ 1,679 $ 355 Total$ 238,504 $ 151 $ 52,945 $ 857 $ 50,447 $ 3,005 $ 2,395 $ 564

Total Summer$ 134,222 Total Winter$ 214,645 Grand Total$ 348,867

Total Supplier Payment - in $1000 Summer$ 144,272 Winter$ 204,465 Total$ 348,737 kWh Rate % difference Adjustment rounded to 5 decimal places 6.9661% Differences - in $1000 Factors -4.9790% Summer$ 10,050 1.07488 -0.0373% Winter$ (10,180) 0.95257 Total$ (130)

Note: These differences are due to rounding and seasonal differences in Bidder Payments (which are based on prior wining bids and Seasonal Payment Factors) and current Rates (based on current seasonal market differentials) Atlantic City Electric Company Attachment 3 Development of BGS Rates Page 4 of 4 June 2022 - May 2023

Atlantic City Electric Company Calculation of June 2022 to May 2023 BGS-RSCP Rates based on results of February 2022 BGS RSCP Auction

Table E Final Resulting BGS Rates (in cents per kWh) - with preliminary kWh rates adjusted by the kWh Rate Adjustment Factor rounded to 4 decimal places

includes energy, G obligations, Ancillary Services, and Renewable Power Cost - adjusted to billing time periods

RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC

Summer - all hrs 7.6431 6.3434 5.8843 5.9877 5.6192 4.7527 5.5803 On-Peak 8.3220 Off-Peak 4.6427

for Block 1 (0-750 kWh/m) usage 6.1054 for Block 2 (>750 kWh/m) usage 7.0354

Winter - all hrs 6.6072 8.4295 6.1546 5.6273 5.7591 5.3867 4.6761 5.3465 On-Peak 8.8822 Off-Peak 4.5901

Table F Spreadsheet Error Checking - Checking of seasonal Customer Revenue and Supplier Payments, based on final actual anticipated revenues and payments

RS RS TOU - BGS MGS - SEC MGS - PRI AGS - SEC AGS - PRI SPL/CSL DDC Total Rate Revenue - in $1000 Summer$ 101,145 $ 61 $ 20,828 $ 331 $ 19,708 $ 1,206 $ 769 $ 224 Winter$ 137,556 $ 89$ 31,976 $ 523 $ 30,588 $ 1,794 $ 1,600 $ 338 Total$ 238,701 $ 150 $ 52,804 $ 854 $ 50,297 $ 3,000 $ 2,369 $ 563

Total Summer$ 144,272 Total Winter$ 204,464 Grand Total$ 348,736

Total Supplier Payment - in $1000 Summer$ 144,272 Winter$ 204,465 Total$ 348,737

Differences - in $1000 Summer$ (0) Winter$ (1) Total$ (1)

Attachment 4

Atlantic City Electric Company Attachment 4 Development of BGS Rates Page 1 of 5 June 2022 - May 2023

Development of Capacity Proxy Price True-Up - $/MWh 2022/2023 Delivery Year 2022/23 Delivery Year Notes: 1 Zonal Capacity Price ($/MW-day) $97.75 as may be determined by the RPM, or its successor, or otherwise 2 Capacity Proxy Price ($/MW-day) $152.06 per Board Order dated 11/18/2020

3 Capacity Proxy Price True-Up - $/MW-day -$54.31 = line 1 - line 2 4 BGS-RSCP Gen Obl - MW 1,741.2 5 Days in Year 365 6 Capacity Proxy Price True-Up Annual Cost -$34,515,625 = line 3 * line 4 * line 5

7 Eligible Tranches 15 from Table A 8 Total Tranches 22 from Table A 9 % of tranches eligible for payment 68.18% = line 7 / line 8

10 Capacity Proxy Price True-Up Cost -$23,533,380 = line 6 * line 9

11 Total Applicable Customer Usage @ bulk system - in MWh 5,797,044 12 Eligible Customer Usage @ bulk system - in MWh 3,952,530 = line 9 * line 11

13 Capacity Proxy Price True-Up - $/MWh -$5.95 = line 10/ line 12 - rounded to 2 decimal places Atlantic City Electric Company Attachment 4 Development of BGS Rates Page 2 of 5 June 2022 - May 2023

Development of Capacity Proxy Price True-Up - $/MWh Capacity Proxy Price True- Capacity Proxy Price True- Up Development for Up Development for Using 2023/2024 Illustrative Data for ACE Winning Suppliers from Winning Suppliers from 2021 BGS-RSCP Auction 2022 BGS-RSCP Auction 2023/24 2023/24 Delivery Year Delivery Year Notes: 1 Zonal Capacity Price ($/MW-day) $155.00 $155.00 as may be determined by the RPM, or its successor, or otherwise 2 Capacity Proxy Price ($/MW-day) $146.51 $118.12 per Board Orders dated 11/18/2020 and XX/XX/2021

3 Capacity Proxy Price True-Up - $/MW-day $8.49 $36.88 = line 1 - line 2 4 BGS-RSCP Gen Obl - MW 1,741.2 1,741.2 5 Days in Year 366 366 6 Capacity Proxy Price True-Up Annual Cost $5,410,431 $23,502,554 = line 3 * line 4 * line 5

7 Eligible Tranches 7 7 from Table A 8 Total Tranches 22 22 from Table A 9 % of tranches eligible for payment 31.82% 31.82% = line 7 / line 8

10 Capacity Proxy Price True-Up Cost $1,721,501 $7,478,086 = line 6 * line 9

11 Total Applicable Customer Usage @ bulk system - in MWh 5,797,044 5,797,044 12 Eligible Customer Usage @ bulk system - in MWh 1,844,514 1,844,514 = line 9 * line 11

13 Capacity Proxy Price True-Up - $/MWh $0.93 $4.05 = line 10/ line 12 - rounded to 2 decimal places Atlantic City Electric Company Attachment 4 Development of BGS Rates Page 3 of 5 June 2022 - May 2023

Development of Capacity Proxy Price True-Up - $/MWh Using 2024/2025 Illustrative Data for ACE 2024/25 Delivery Year Notes: 1 Zonal Capacity Price ($/MW-day) $100.00 as may be determined by the RPM, or its successor, or otherwise 2 Capacity Proxy Price ($/MW-day) $87.98 per Board Order dated XX/XX/2021

3 Capacity Proxy Price True-Up - $/MW-day $12.02 = line 1 - line 2 4 BGS-RSCP Gen Obl - MW 1,741.2 5 Days in Year 365 6 Capacity Proxy Price True-Up Annual Cost $7,639,068 = line 3 * line 4 * line 5

7 Eligible Tranches 7 from Table A 8 Total Tranches 22 from Table A 9 % of tranches eligible for payment 31.82% = line 7 / line 8

10 Capacity Proxy Price True-Up Cost $2,430,613 = line 6 * line 9

11 Total Applicable Customer Usage @ bulk system - in MWh 5,797,044 12 Eligible Customer Usage @ bulk system - in MWh 1,844,514 = line 9 * line 11

13 Capacity Proxy Price True-Up - $/MWh $1.32 = line 10/ line 12 - rounded to 2 decimal places Atlantic City Electric Company Attachment 4 Development of BGS Rates Page 4 of 5 June 2022 - May 2023

Table A With Additional Line Item Calculation of June 2023 to May 2024 BGS-RSCP Rates Illustrative Purposes Only for ACE

Table A Auction Results remaining remaining portion of portion of 36 36 month bid - 2021 month bid - 36 month bid - line # Specific BGS-RSCP Auction >> auction 2022 auction 2023 auction Notes:

1 Winning Bid - in $/MWh $ 64.20 $ 64.20 $ 64.20 winning Bids 1A 23/24 Capacity Proxy Price True-up - in $/MWh $ 0.93 $ 4.05 entered after 2023 BGS Auction 1B Total - in $/MWh $ 65.13 $ 68.25 $ 64.20 = line 1 + line 1A

2 # of Tranches for Bid 7 7 8 from then current Bid 3 Total # of Tranches 22 22 22 from then current Bid

Payment Factors 4 Summer 1.0000 1.0000 1.0000 from then current Bid Factor Spreadsheet 5 Winter 1.0000 1.0000 1.0000 from then current Bid Factor Spreadsheet

Applicable Customer Usage @ bulk system - in MWh 6 Summer MWh 2,398,232 from current Bid Factor Spreadsheet 7 Winter MWh 3,398,812

Total Payment to Suppliers - in $1000 8 Summer $ 49,699 $ 52,080 $ 55,988 = ((1) * (2)/(3) * (4) * (6)) + ((1A) * (2)/(3) * (6)) 9 Winter $ 70,434 $ 73,808 $ 79,347 = ((1) * (2)/(3) * (5) * (7)) + ((1A) * (2)/(3) * (7)) 10 Total $ 120,133 $ 125,888 $ 135,335

Average Payment to Suppliers - in $/MWh 11 Summer $ 65.79 = sum(line 8) / (6) - rounded to 2 decimal places 12 Winter $ 65.79 = sum(line 9) / (7) - rounded to 2 decimal places

13 Total weighted average $ 65.79 <<< used in calculation of = sum(line 10) / [ (6) + (7)] Customer Rates rounded to 2 decimal places Atlantic City Electric Company Attachment 4 Development of BGS Rates Page 5 of 5 June 2022 - May 2023

Table A With Additional Line Item Calculation of June 2024 to May 2025 BGS-RSCP Rates Illustrative Purposes Only for ACE

Table A Auction Results remaining remaining portion of portion of 36 36 month bid - 2022 month bid - 36 month bid - line # Specific BGS-RSCP Auction >> auction 2023 auction 2024 auction Notes:

1 Winning Bid - in $/MWh $ 64.20 $ 64.20 $ 64.20 winning Bids 1A 24/25 Capacity Proxy Price True-up - in $/MWh $ 1.32 entered after 2024 BGS Auction 1B Total - in $/MWh $ 65.52 $ 64.20 $ 64.20 = line 1 + line 1A

2 # of Tranches for Bid 7 8 7 from then current Bid 3 Total # of Tranches 22 22 22 from then current Bid

Payment Factors 4 Summer 1.0000 1.0000 1.0000 from then current Bid Factor Spreadsheet 5 Winter 1.0000 1.0000 1.0000 from then current Bid Factor Spreadsheet

Applicable Customer Usage @ bulk system - in MWh 6 Summer MWh 2,398,232 from current Bid Factor Spreadsheet 7 Winter MWh 3,398,812

Total Payment to Suppliers - in $1000 8 Summer $ 49,997 $ 55,988 $ 48,989 = ((1) * (2)/(3) * (4) * (6)) + ((1A) * (2)/(3) * (6)) 9 Winter $ 70,856 $ 79,347 $ 69,428 = ((1) * (2)/(3) * (5) * (7)) + ((1A) * (2)/(3) * (7)) 10 Total $ 120,853 $ 135,335 $ 118,418

Average Payment to Suppliers - in $/MWh 11 Summer $ 64.62 = sum(line 8) / (6) - rounded to 2 decimal places 12 Winter $ 64.62 = sum(line 9) / (7) - rounded to 2 decimal places

13 Total weighted average $ 64.62 <<< used in calculation of = sum(line 10) / [ (6) + (7)] Customer Rates rounded to 2 decimal places

Attachment 5 Atlantic City Electric Company Attachment 5 Development of BGS Rates Page 1 of 1 June 2022 - May 2023

Development of Assumed Transmission Price in Bid Calculation for 2020/2021

remaining portion of 36 month bid - line # 2020/21 filing Notes:

1 Eligible Tranches 8 2 Total Tranches 22 3 Tranche % 36.36% = line 1 / line 2 4 Transmission Obligations (MW) 1996.4 Obligations from filng years 5 Adjustment Transmission Obligation (MW) 726.0 = line 3 * line 4 6 NITS Rate ($/MW-yr) $ 54,394.71 NITS Rates from from 2020 7 Payment ($/yr) $ 39,488,979 = line 5 * line 6 8 Pre Loss Usage (MWh) 5,886,173 Applicable usage from filing years 9 Allocated Usage (MWh) 2,140,426 = line 3 * line 8 10 Transmission Price ($/MWh) $ 18.45 = line 7 / line 9 (To Attachment 3, Table A, Line 1B) In the Matter of the Provision of Basic Generation Service for the Period Beginning June 1, 2022 BPU Docket No. ER21030631 Service List

Applebaum, David A. - [email protected] Peterson, Stacy – [email protected] Artale, Carol - [email protected] Rantala, Stacey - [email protected] Atzl, Jr., William A. - [email protected] Rattansi, Aliraza - [email protected] Beck, Michael - [email protected] Rawlings, Lyle - [email protected] Bevan, Murray E. - [email protected] [email protected] Bhatia, Dinkar - [email protected] [email protected] Brabston, Robert - [email protected] Richter, David K. - [email protected] Brand, Stefanie - [email protected] Riepl, Glenn - [email protected] Burcat, Bruce H. - [email protected] Roach, Craig - [email protected] Camacho-Welch, Aida - [email protected] Rodriguez, Jesse A. - [email protected] Carley, John L. - [email protected] Romero, Marjorie - [email protected] Catanach, James - [email protected] Ruggiero, Cheryl M. - [email protected] Chang, Max - [email protected] Secretary of the Board - [email protected] Codd, Chris - [email protected] Silverman, Abe - [email protected] Comes, Margaret - [email protected] Spielvogel, Larry - [email protected] Davies, Matthew - [email protected] Spricigo, Jennifer - [email protected] Depillo, Raymond - [email protected] [email protected] DeVito, Susan - [email protected] Thomas, Glen - [email protected] Dworetzky, Jeanne J. - [email protected] Thompson, Howard O. - [email protected] Eckert, Joshua - [email protected] Torkelson, Christopher - [email protected] Filewicz, Myron - [email protected] Tudor, Daniel A. - [email protected] Flanagan, Paul - [email protected] Urbish, Madaline - [email protected] Forshay, Paul F. - [email protected] Wadsworth, Joe - [email protected] Gabel, Steven - [email protected] Wand, T. David - [email protected] Gallagher, Sean - [email protected] Weber, Sharon - [email protected] Gerard, Morgan - [email protected] Weisband, Heather - [email protected] Gibbs, Robert - [email protected] Weissman, Matthew - [email protected] Goldenberg, Steven - [email protected] Williams, Aundrea - [email protected] Gupta, Divesh - [email protected] [email protected] Hahn, Thomas M. - [email protected] Hanks, Marc A. - [email protected] Hoatson, Thom - [email protected] [email protected] Holub, John - [email protected] Hubschman, Don - [email protected] Jacob, Shajan - [email protected] Kaufman, Adam - [email protected] Klots, Cynthia - [email protected] LaCasse, Chantale - [email protected] Laskey, James - [email protected] Layugan, Debora - [email protected] Leyden, Shawn P. - [email protected] Lipman, Brian O. - [email protected] Maher, Kathleen K. - [email protected] Marks, Deborah S. - [email protected] McGarvey, Christine - [email protected] Megdal, Ira G. - [email protected] Minogue, Holly - [email protected] Moran, Ryan - [email protected] Moran, Terrence J. - [email protected] Morgan, Karen - [email protected] Mossburg, Frank - [email protected] Moury, Karen - [email protected] Myers, James C. - [email protected] Northcutt, Rachel - [email protected] Novak, Diana N. - [email protected] Orlandi, Kathleen - [email protected] Passanante, Philip J. - [email protected] Peng, Yongmei - [email protected]